Hydraulic fracturing in kerogen-rich unconventional formations

ABSTRACT

The subject matter of this specification can be embodied in, among other things, a method for treating a geologic formation that includes providing a hydraulic fracture model, providing a first value representative of a volume of kerogen breaker in a fracturing fluid, determining a discrete fracture network (DFN) based on the hydraulic fracture model and the first value, determining a geomechanical model based on the DFN and a reservoir model based on the DFN, determining a hydrocarbon production volume based on the geomechanical model and the reservoir model, adjusting the first value based on the hydrocarbon production volume, and adjusting a volume of kerogen breaker in the fracturing fluid to a hydrocarbon reservoir based on the adjusted first value.

This application is a continuation of and claims the benefit of priorityto U.S. patent application Ser. No. 15/190,687, filed on Jun. 23, 2016,the contents of which are hereby incorporated by reference.

TECHNICAL FIELD

This disclosure relates to the adjustment of quantities of hydraulicfracturing agents provided to kerogen-rich reservoirs for hydrocarbonextraction.

BACKGROUND

In some instances, a geologic formation, such as shale, may be fracturedto initiate or enhance hydrocarbon production from the formation.Fracturing typically involves pumping a fluid into a wellbore at aparticular pressure to break, or “fracture,” the geologic formation. Thehydrocarbon fluid may then flow through the fractures and cracksgenerated by the fracturing process to the wellbore, and ultimately tothe surface. In some instances, the fracturing process includes multiplestages of high-pressure fluid circulation into the wellbore, which mayinvolve increased costs and complexities.

SUMMARY

In general, this document describes the use of hydraulic fracturingagents for hydrocarbon extraction in kerogen-rich unconventionalformations.

In a first aspect, a method for treating a geologic formation includesproviding a hydraulic fracture model, providing a first valuerepresentative of a volume of kerogen breaker in a fracturing fluid,determining a discrete fracture network (DFN) based on the hydraulicfracture model and the first value, determining a geomechanical modelbased on the DFN and a reservoir model based on the DFN, determining ahydrocarbon production volume based on the geomechanical model and thereservoir model, adjusting the first value based on the hydrocarbonproduction volume, and adjusting a volume of kerogen breaker in thefracturing fluid to a hydrocarbon reservoir based on the adjusted firstvalue.

Various implementations can include some, all, or none of the followingfeatures. The method can further include providing a second valuerepresentative of an amount of heat to apply to the hydrocarbonreservoir, adjusting the second value based on the hydrocarbonproduction volume, wherein, determining the DFN can be further based onthe second value, and adjusting the amount of heat to apply to thehydrocarbon reservoir is further based on the adjusted second value. Theamount of heat can have a heating cost, the hydrocarbon productionvolume can have a market value, and adjusting the second value caninclude determining a difference between the market value and theheating cost and adjusting the second value to increase the difference.The method can further include extracting a volume of hydrocarbon fromthe hydrocarbon reservoir based on the volume of kerogen breaker in thefracturing fluid, and adjusting the second value based on the extractedvolume. The volume of kerogen breaker in the fracturing fluid can have amaterial cost, the hydrocarbon production volume can have a marketvalue, and adjusting the first value can include determining adifference between the market value and the material cost and adjustingthe first value to increase the difference. The DFN can be descriptiveof one or more of new fractures that are predicted to be created basedon the hydraulic fracturing model, modified shale properties predictedto be modified based on the hydraulic fracturing model, and reactivatedfractures that are predicted to be reactivated based on the hydraulicfracturing model and the modified shale properties. The hydraulicfracture model can be configured to determine the DFN further based onone or more of in-situ stresses in the reservoir field, pore pressuresin the reservoir field, injection plans of a fracturing job,heterogeneity in the reservoir formation, elastic stiffness propertiesof reservoir rocks, plastic strength properties of reservoir rocks, andmechanical properties of heterogeneities, and the DFN can include anumber of fractures each characterized by one or more of fracturelength, fracture width, fracture height, and fracture orientation. Thegeomechanical model can be configured to predict the evolution of atleast one of stress fields, deformation, and damage in the reservoirbased on one or more of in-situ stresses in the reservoir field, porepressures in the reservoir field, rock masses of reservoir layers, theDFN, constitutive models of rock mass that describestress-deformation-failure processes of reservoirs under loading modes,mechanical properties of rock masses, mechanical properties offractures, fluid mechanical interaction parameters, and thermalmechanical coupling parameters. The reservoir model can be configured topredict the evolution of multiphase flow and pressure fields in thereservoir based on one or more of reservoir pressure distributionparameters, reservoir temperature distribution parameters, multiphaseflow models for fluid flow in rock, multiphase flow models for fluidflow in the DFN, thermal conduction models, thermal convection models,porosity parameters, permeability parameters, saturation parameters,thermal conduction property parameters, thermal convection propertyparameters, well location parameters, well drawdown plan parameters, andwell temperature parameters. The method can also include extracting avolume of hydrocarbon from the hydrocarbon reservoir based on the volumeof kerogen breaker in the fracturing fluid, and adjusting the firstvalue based on the extracted volume.

In a second aspect, a system for hydraulic fracturing includes ahydraulic fracture model configured to determine a discrete fracturenetwork (DFN) based on a first value representative of a volume ofkerogen breaker in a fracturing fluid, a geomechanical model based onthe DFN and a reservoir model based on the DFN, the geomechanical modeland the reservoir model configured to determine a hydrocarbon productionvolume, and an adjustment module configured to adjust the first valuebased on the hydrocarbon production volume.

Various implementations can include some, all, or none of the followingfeatures. The system can also include a valve configured to adjust avolume of kerogen breaker in the fracturing fluid to a hydrocarbonreservoir based on the adjusted first value. The hydraulic fracturemodel can be configured to determine the discrete fracture network (DFN)further based on a second value representative of an amount of heat toapply to the hydrocarbon reservoir, and the adjustment module can befurther configured to adjust the second value based on the hydrocarbonproduction volume. The amount of heat can have a heating cost, thehydrocarbon production volume can have a market value, and theadjustment model can be further configured to adjust the second valuebased on determining a difference between the market value and theheating cost and adjusting the second value to increase the difference.The system can also include a valve configured to adjust delivery ofheat provided to a hydrocarbon reservoir based on the adjusted secondvalue. The volume of kerogen breaker in the fracturing fluid can have amaterial cost, the hydrocarbon production volume can have a marketvalue, and the adjustment model can be further configured to adjust thesecond value based on determining a difference between the market valueand the material cost and adjusting the first value to increase thedifference. The DFN can be descriptive of one or more of new fracturesthat are predicted to be created based on the hydraulic fracturingmodel, modified shale properties predicted to be modified based on thehydraulic fracturing model, and reactivated fractures that are predictedto be reactivated based on the hydraulic fracturing model and themodified shale properties. The hydraulic fracture model can beconfigured to determine the DFN further based on one or more of in-situstresses in the reservoir field, pore pressures in the reservoir field,injection plans of a fracturing job, heterogeneity in the reservoirformation, elastic stiffness properties of reservoir rocks, plasticstrength properties of reservoir rocks, and mechanical properties ofheterogeneities, and the DFN can include a number of fractures eachcharacterized by one or more of fracture length, fracture width,fracture height, and fracture orientation. The geomechanical model canbe configured to predict the evolution of at least one of stress fields,deformation, and damage in the reservoir based on one or more of in-situstresses in the reservoir field, pore pressures in the reservoir field,rock masses of reservoir layers, the DFN, constitutive models of rockmass that describe stress-deformation-failure processes of reservoirsunder loading modes, mechanical properties of rock masses, mechanicalproperties of fractures, fluid mechanical interaction parameters, andthermal mechanical coupling parameters. The reservoir model can beconfigured to predict the evolution of multiphase flow and pressurefields in the reservoir based on one or more of reservoir pressuredistribution parameters, reservoir temperature distribution parameters,multiphase flow models for fluid flow in rock, multiphase flow modelsfor fluid flow in the DFN, thermal conduction models, thermal convectionmodels, porosity parameters, permeability parameters, saturationparameters, thermal conduction property parameters, thermal convectionproperty parameters, well location parameters, well drawdown planparameters, and well temperature parameters.

The systems and techniques described here may provide one or more of thefollowing advantages. First, a system can identify amounts ofkerogen-reducing or removing agents that have corresponding estimatesfor volumes of extracted hydrocarbons. Second, the system can increasethe efficiency of extracting volumes of hydrocarbons based onpredetermined amounts of kerogen-reducing agents to be used. Third, thesystem can increase the profitability of hydrocarbon extractionprocesses in kerogen-rich formations where kerogen-reducing agents arein use.

The details of one or more implementations are set forth in theaccompanying drawings and the description below. Other features andadvantages will be apparent from the description and drawings, and fromthe claims.

DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram of an example of a well system.

FIG. 2 is a schematic diagram that shows an example of a control system.

FIG. 3 is flow chart that shows an example of a process for adjustingkerogen breaker volume values.

DETAILED DESCRIPTION

FIG. 1 is a schematic diagram of an example well system 10. The wellsystem 10 includes a fracturing device 45, through which kerogen breakerin fracturing fluids or heat or both may be applied on a hydrocarbonproduction field such as a rock formation 42 of a kerogen-rich,unconventional subterranean zone 40.

In some instances, in the kerogen-rich shales, the extensive existenceof kerogen may have significant influence upon the overall mechanicalbehavior of the shales. However, due to the micro- or nano-scale of somekerogen volumes, it is impractical to measure the mechanical propertiesand behaviors of kerogen in conventional geomechanics testingconfigurations, such as a uniaxial test, a triaxial test, or a Braziliandisc test.

Generally speaking, kerogens can demonstrate strain-softening, ductilemechanical behavior when subjected to tensile load. An implication ofthis observation is that kerogen can have a negative impact on theinitiation and propagation of fractures and sustainability of fractureopening in kerogen-rich unconventional reservoir formations. In someimplementations, these negative impacts can be reduced by addingbreaker, heat, or other treatments in the fracturing fluids. The dose ofbreaker, for example, can determined by the tradeoff between the cost ofadding breakers into fracturing fluids and the value of the resultingincrease in hydrocarbon (for example, petrochemical, oil) production. Insome implementations, the amount of treatment can be determined by arecursive numerical simulation, which takes stress, pressure andmechanical properties of reservoir formation, including kerogen domains,and fracturing fluid properties as inputs and can predict the fractureextension, sustainability, and productivity of the stimulated reservoir.In some implementations, the amount of treatment can be determined inreal time by feedback control process, which takes target and actualhydrocarbon extraction rates as inputs and can adjust the amount oftreatment to approach the target extraction rate. In someimplementations, the feedback control process can take a market valuefor hydrocarbons and the costs of treatments as inputs, and can adjustthe amount of treatment to adjust a net financial gain.

The fracturing compounds, in some implementations, may decompose orremove at least part of the kerogen domains in the rock formation 42.For example, exposure of the rock formation 42 to breaker compounds orheat or both can at least partly dissolve kerogen, easing the flow ofhydrocarbons through the rock formation 42 to a wellbore 20.

As shown, the well system 10 accesses a subterranean zone 40 (which canbe a formation, a portion of a formation or multiple formations), andprovides access to hydrocarbons located in such subterranean zone 40. Inan example implementation of system 10, the system 10 can be used for adrilling operation in which a downhole tool 50 can include or be coupledwith a drilling bit. In another example implementation of system 10, thesystem 10 can be used for a completion, for example, hydraulicfracturing, operation in which the downhole tool 50 can include or becoupled with a hydraulic fracturing tool. Thus, the well system 10 canallow for a drilling or fracturing or stimulation operations.

The well system 10 also includes a control system 19, for example,microprocessor-based, electro-mechanical, or otherwise, that candetermine or control the amount of breaker compound(s), heat, or both tobe applied downhole to fracture the kerogens in the rock formation 42.

In hydraulic fracturing implementations, the bottom hole pressures usedto initiate fractures around the wellbore 20 are called breakdownpressure (P_(b)). For impermeable rock P_(b) can be related to in-situstress and reservoir rock tensile strength, and can be expressed as:P _(b)=3σ_(min)−σ_(max)+σ^(T)

where σ_(max) and σ_(min) are maximum and minimum in-situ effectiveprincipal stress, respectively; σ^(T) is the tensile strength of rock;P_(b) is the pressure above the initial in-situ pore pressure that isrequired to break down the formation.

In some kerogen rich shales (KRS), the kerogen fibers can be fine butcan exist across large volumes. Their presence can be described bywidespread distributed “spider webs”. The densely distributed kerogenscan have various implications upon hydraulic fracturing. For example,kerogen can add extra strength to the reservoir rock, so KRS can havehigher tensile strength than kerogen free shale (KFS), which can resultin a higher breakdown pressure being needed to initiate the fracture inKRS. In another example, kerogen can have relatively high tensilestrength at high tensile deformation, which can raise fracturepropagation pressure to a higher pressure level than fracturing KFS inwhich the tensile strength usually drops to zero quickly after theinitial fracture. In yet another example, after the proppants are placedin the fractures and the bottom hole pressured decreased, the kerogencan bounce back thereby imposing additional confining compressive stressto the proppants in addition to the in-situ stress of reservoirformation, which can cause additional embedment of proppants into theformation resulting in extra reduction of the fracture aperture.

Kerogen has negative impact on initiation and propagation of fractures,and the sustainability of fracture opening in kerogen-richunconventional reservoir formations; fracturing fluid shall reverse thenegative effect of elastic rebound of kerogen after the initialfracturing opening, including (1) use breaker to decompose, at leastpartially, or (2) use other materials or methods, to remove at leastpart of kerogen domains.

In the oilfield, commonly used oxidizers can include persulfate,bromate, H₂O₂, H₂O₂-urea, and H₂O₂-carbonate complexes. Cl-containedoxidizers can be used as well. In some implementations, persulfate orbromate or both can be good enough to remove all or part of kerogen. Insome implementations, iron (Fe) in kerogen can act as a catalyst tospeed up reactions. In some implementations, the FeS₂ in pyrite can beoxidized to release Fe ions.

Two series of tests, each consisting of four tests, were conducted tobreak kerogen under laboratory conditions. In the first series of tests,the same amount of breaker compound was used to break the same amount ofkerogen, but the breaking time was different in each test. In the secondseries tests, different amounts of breaker compound was used to breakthe same amount of kerogen with same breaking times.

In the first series of tests, about 50 mg of kerogen and 500 mg ofsodium bromate were added to 20 ml of deionized water in each sample,and placed in a 300 F bath for 8, 16, 32, and 64 hours, respectively.The residue was filtered out, dried, and weighed. The tests show thatthis type of treatment can be useful to at least partly remove kerogen.

The Testing Conditions and Results are Provided in Table 1.

TABLE 1 Weight reduction of kerogen with same amount of sodium bromate(500 mg) but different time. Kerogen initial Residue Weight Hours at 300F. weight weight reduction (hours) (mg) (mg) (%) 8 48.0 22 54 16 49.1 1178 32 48.8 7 86 64 49.7 7 86

In the second series of test, around 50 mg of kerogen and 50, 100, 200,or 400 mg, respectively, of sodium bromate were added to 20 ml ofdeionized water in each sample, and placed in a 300 F bath for 48 hours.The residue was filtered out, dried, and weighed. The testing conditionsand results are presented in Table 2.

TABLE 2 Weight reduction of kerogen with different amount of sodiumbromate but same time (48 hours). Kerogen initial Residue Weight NaBrO3weight weight weight reduction (mg) (mg) (mg) (%) 50.0 50.3 35 30 99.850.5 29 43 200.1 50.8 18 65 400.8 50.9 7 86

In the first series of tests, ˜500 mg of NaBrO₃ caused a kerogen weightreduction of about 86% after sufficient time. So it appears that about400-500 mg of NaBrO₃ can be used to break about 50 mg of kerogen. Insome implementations, it may not be necessary to break down 100% of theorganic materials in kerogen. For example, as long as kerogen isweakened to such an extent that it will not significantly affectfracture initiation and propagation, the treatment can be considered tobe sufficient.

FIG. 2 is a schematic diagram that shows an example of a control system200. In some embodiments, the control system 200 can be implemented bythe example control system 19 of FIG. 1. As discussed above, kerogen canbe at least partly dissolved by chemical means, depending on the amountof breaker (for example, sodium bromate) and treatment time used.However, undertaking such a pre-treatment operation, the time requiredto perform the operation, and the volume of the breaker material used toperform the operation can add extra cost to the process of extractinghydrocarbons when compared with hydraulic fracturing processes withoutsuch pre-treatment. On the other hand, in some implementations, removalor reduction of kerogen domains along the fractures can generate longerand wider fractures in hydraulic fracturing, which can enhance wellproductivity. In some kerogen treatment designs, the parameters of thepre-treatment operation can be adjusted to increase the net financialgain from the kerogen breaking treatment, based on the differencebetween the expense of the operation (for example, cost of an amount ofbreaker compound used) and the value of any additional hydrocarbon thatcan be extracted as a result. The control system 200 is configured todetermine such pre-treatment parameters, apply them to the rock zone 40of FIG. 1, and estimate the effect upon the extraction of hydrocarbonsout of the wellbore 20.

The control system 200 implements a shale stiffness and strength model205. In some implementations, the model 205 can be implemented ascomputer instructions stored on a computer-readable medium andexecutable by one or more processors. Alternatively or in addition, themodel 205 can be implemented in hardware or firmware or a combination ofhardware, firmware and software. The model 205 is configured to receivea kerogen breaker volume value 210 and determine a collection ofmodified shale formation properties. In some implementations, thekerogen breaker volume value 210 can be received from an externalsource, for example a predetermined startup value provided by a storagesystem, a startup value provided by a pseudorandom number generator, avalue provided by human operator, or any other appropriate source. Thekerogen breaker volume value 210 represents a quantity of a selectedbreaker compound that is to be delivered down hole (for example, to therock formation 42). The shale stiffness and strength model 205 isconfigured to determine an amount by which a selected kerogen-richenvironment such as the rock formation 42 can be affected by theapplication of a selected volume of kerogen breaker. For example, shalestiffness and strength in the rock formation 42 can be reduced by X %for a Y volume of kerogen breaker. In some implementations, thecollection of modified shale formation properties can represent theestimated stiffness and strength of shale in the selected kerogen-richenvironment as a result of providing the volume of kerogen breakerrepresented by the kerogen breaker volume value 210.

The shale stiffness and strength model 205 is also configured to receivea bottom hole heat up value 212 to determine the collection of modifiedshale formation properties. In some implementations, the bottom holeheat up value 212 can be received from an external source, for example apredetermined startup value provided by a storage system, a startupvalue provided by a pseudorandom number generator, a value provided byhuman operator, or any other appropriate source. The bottom hole heat upvalue 212 represents an amount of heat energy that is to be delivereddown hole (for example, to the rock formation 42). For example, atemperature rise of 50° C. can be selected to at least partly dissipatekerogens. In some implementations, the heat energy can be providedchemically. For example, an acid and a base can both be delivered downhole, and the resulting reaction can create heat that can dissipatekerogen. In some implementations, the heat energy can be providedelectrically. For example, microwave or radio frequency energy can bedelivered downhole to heat the rock formation 42. In someimplementations, other heating techniques can be used (for example,steam, radiation, vibration, ultrasound, lasers). The shale stiffnessand strength model 205 is configured determine an amount by which aselected kerogen-rich environment such as the rock formation 42 can beaffected by the application of a selected amount of heat delivered downhole. For example, shale stiffness and strength in the rock formation 42can be reduced by M % for an N amount of heat energy or temperaturerise. In some implementations, the collection of modified shaleformation properties can represent the estimated stiffness and strengthof shale in the selected kerogen-rich environment as a result ofproviding the amount of bottom hole heat up represented by the bottomhole heat up value 212. Without adding breaker, due to the hindrance ofrubbery kerogen domains, the breakdown pressure observed duringhydraulic fracturing can be larger. However, in examples in whichbreaker is added, kerogen domains can be at least partially broken andthe hindrance can be weakened, resulting in smaller breakdown pressurevalues.

The collection of modified shale formation properties determined by theshale stiffness and strength model 205 are received by a hydraulicfracture model 220. In some implementations, the model 220 can beimplemented as computer instructions stored on a computer-readablemedium and executable by one or more processors. Alternatively or inaddition, the model 220 can be implemented in hardware or firmware or acombination of hardware, firmware and software. In some implementations,the hydraulic fracture model 220 can also be configured to receiveadditional information about a well system such as the well system 10.For example, the hydraulic fracture model 220 can accept informationincluding in-situ stresses and pore pressure in the reservoir field,injection plans for a fracturing job, heterogeneity in the reservoirformation, elastic stiffness properties of reservoir rocks, plasticstrength properties of reservoir rocks, and mechanical properties ofheterogeneities. In some implementations, some of these properties canbe measured in a rock mechanics lab and provided for use by thehydraulic fracture model 220.

The hydraulic fracture model 220 simulates a main hydraulic fracturingstimulation based on the collection of modified shale formationproperties. In the simulation performed by the hydraulic fracture model220, some existing natural fractures can be reactivated, new fracturescan be created, and proppants can be placed in the created fractures. Asa result of this simulation, a stimulated reservoir volume (SRV)consisting of new fractures or reactivated natural fractures (or both)will be determined. The output of hydraulic fracture model 220 is adiscrete fracture network (DFN) consisting of a description of a numberof fractures, wherein each fracture can be characterized by length,width, height, and orientation.

The system 200 includes a geomechanical model 230. In someimplementations, the model 230 can be implemented as computerinstructions stored on a computer-readable medium and executable by oneor more processors. Alternatively or in addition, the model 230 can beimplemented in hardware or firmware or a combination of hardware,firmware and software.

The geomechanical model 230 is configured to receive the DFN andestimate an amount of hydrocarbon production that the rock formation 42can provide based on the DFN. In some implementations, the geomechanicalmodel 230 can be configured to receive additional information about awell system such as the well system 10. For example, the geomechanicalmodel 230 can accept information including in-situ stresses and porepressure in the reservoir field, rock mass of reservoir layers,constitutive models of rock mass that describe thestress-deformation-failure process of reservoir under various loadingmodes, mechanical properties of rock mass, mechanical properties offractures, fluid mechanical interaction parameters, and thermalmechanical coupling parameters. In some implementations, some of theseproperties can be measured in a rock mechanics lab and provided for useby the geomechanical model 230.

The system 200 includes a reservoir model 232. In some implementations,the model 232 can be implemented as computer instructions stored on acomputer-readable medium and executable by one or more processors.Alternatively or in addition, the model 232 can be implemented inhardware or firmware or a combination of hardware, firmware andsoftware.

The reservoir model 232 is configured to receive the DFN and estimate anamount of hydrocarbon production that the rock formation 42 can providebased on the DFN. In some implementations, the reservoir model 232 canbe configured to receive additional information about a well system suchas the well system 10. For example, the reservoir model 232 can acceptinformation including initial reservoir pressure distributioninformation, reservoir temperature distribution information, multiphaseflow models for fluid flow in rock, multiphase flow models for fluidflow in the DFN, thermal conduction models, and convection models, rockporosity, rock permeability, saturation levels, thermal conductionproperties of rock, convective properties of rock, well location,drawdown plans, and temperature at the production well.

The geomechanical model 230 and the reservoir model 232 arebidirectionally coupled to each other. For example, the reservoir model232 can be at least partly driven by a drawdown plan at the well system10. In examples such as this, after thermal and fluid flow modeling isperformed, updated pore pressure and temperature parameters can betransferred from the reservoir model 232 to the geomechanics model 230.In such examples the geomechanical modeling can be performed to bringthe system to equilibrium, then the estimated deformation, mechanicaldamage, and failure in the rock formation 42 can be used to estimateupdated porosity and permeability parameters, and the deformation of theDFN can be used to estimate the updated aperture or other geometricparameters of the DFN. In such examples, updated geometric or mechanicalproperties (or both) of rock mass or the DFN (or both the rock mass andthe DFN) can then be transferred from the geomechanical model 230 to thereservoir model 232, and the reservoir model 232 can perform furtherestimation based on these updated parameters.

The output of the reservoir model 232 and the geomechanical model 230 isan estimated production value 240. As an example, the following ideal“Darcy”, steady state, radial flow equation can be used to calculate theinflow performance of a fully penetrating, damaged, vertical, open holewell in a homogeneous formation.

$q_{w} = \frac{0.00708{{kh}\left( {p_{r} - p_{w}} \right)}}{B\;{\mu\left\lbrack {{\ln\left( \frac{r_{e}}{r_{w}} \right)} + S} \right\rbrack}}$where q_(w) is the well flow rate; k is permeability (mD); h is thethickness of reservoir layer (ft); p_(r) is the reservoir pressure(psi); p_(w) is the flowing bottom hole pressure (psi); B is theformation volume factor; μ is the viscosity of reservoir fluid (cp);r_(e) is drainage radius (ft); r_(w) is the well radius (ft); S is theskin factor.Shales are anitropic and heterogeneous, and the fluid flow relatedparameters of shale, such as permeability, skin factor, fluid viscosity,and any other appropriate parameter of shale fluid flow, can all evolvedynamically with the stress state of the rock matrix and fractures. Forthese types of complex systems, no analytical solutions exist to predictthe production rate. Instead, a coupling of geomechanical models andreservoir models can be implemented to make reliable predictions, inwhich the geomechanical model is used to update the stress and porepressure based on the updated pore pressure in the reservoir model,while the updated stress and pore pressure are used to update thepermeability and porosity of rock matrix (and aperture and pressuredistribution along fractures) in reservoir models to be used in the nextstep of computation in reservoir model.

The estimated production value 240 represents an accumulated productionof hydrocarbon. An adjustment module 250 can then determine an updatedkerogen breaker volume value to be provided to the shale stiffness andstrength model 205 based on the kerogen breaker volume value 210 and theestimated production value 240. The adjustment module 250 can alsodetermine an updated bottom hole heat up value to be provided to theshale stiffness and strength model 205 based on the bottom hole heat upvalue 212 and the estimated production value 240.

In some implementations, the system 200 can be run multiple times toapproach a selected objective. For example, the adjustment model can beconfigured to perform a sweep or search of various kerogen breakervolume values 210 or bottom hole heat up values 212 or both to determinea range of resulting estimated production values 240.

In some implementations, the resulting estimated production values 240can be analyzed to identify an estimated production value 240 thatapproaches a target parameter. For example, the estimated productionvalue 240 having the highest estimated value can be selected, and thekerogen breaker volume value 210 or bottom hole heat up value 212 (orboth) that corresponds to the selected estimated production value 240can be identified and used to configure production in the well system10.

The updated kerogen breaker volume value is also provided as an input toa valve 260. The valve 260 is configured to receive kerogen breakervolume values and control a flow of kerogen breaker compound that isdelivered to the rock formation 42. For example, if the system 200determines that 2000 L of a selected breaker is to be delivered downhole, then the valve 260 can be operated to provide 2000 L of thebreaker to the rock formation 42.

In a similar manner, the updated bottom hole heat up value is alsoprovided as an input to a valve 262. The valve 262 is configured tobottom hole heat up values and control an amount of heat that isdelivered to the rock formation 42. For example, if the system 200determines that the rock formation 42 is to be raised 40° F., then thevalve 262 can be operated to provide one or more volumes ofheat-generating chemical reactants, steam, or other agents correspondingto the identified heat rise to the rock formation 42. In someembodiments, the valve 262 can be replaced by an electrical or othercontrol mechanism. For example, an electrical switch or amplifier can beused to determine a corresponding amount of electrical, RF, microwave,or other energy to be provided to the rock formation 42. In anotherexample, a mechanical oscillator or other vibratory mechanism (forexample, ultrasound or extremely low frequency—ELF—sound) can be used tocreate heat energy down hole.

In some implementations, the breaker compound can have an associatedmaterial cost (for example, a per-volume unit cost), and a kerogenbreaker compound cost can be determined based on the material cost andthe kerogen breaker volume value 210. For example, if a selected breakercompound cost $0.10 per liter and the kerogen breaker volume valuerepresented 1000 liters, then the kerogen breaker compound cost would be$100.

In some examples where the bottom hole heat up is provided chemically,the chemical reactants used can have an associated per-unit heating cost(for example, a per unit volumetric cost of the reactants), and aheating cost can be determined based on the per-unit heating cost andthe bottom hole heat up value 212. For example, it may be known that1000 liters of a selected acid and 500 liters of a selected base cost$0.25/liter each, and therefore a 20° C. rise may consume(1000+500)*20=30000 liters of reactants and have a heating cost of3000010.25=$7500.

In some examples where the bottom hole heat up is provided electrically,the electrical power can have an associated per-unit heating cost (forexample, a per kilowatt cost for electricity), and the heating cost canbe determined based on the per-unit heating cost on the bottom hole heatup value 212. In some implementations, other heating techniques can beused (for example, steam, radiation, vibration, ultrasound, extreme lowfrequency—ELF, lasers), and each heating technique can have its ownper-unit heating cost that can be used along with the bottom hole heatup value 212 to determine the heating cost.

In some implementations, the system 200 can be configured to identifyvalues for the kerogen breaker volume value 210 or the bottom hole heatup value 212 or both based on the per-unit costs of the kerogen breakercompound, heating costs, and the per-unit value of the estimatedproduction 240. For example, the adjustment module 250 can be configuredto identify an estimated production value 240 that approaches amaximized difference (for example, profit margin) between the value ofthe estimated production value 240 and the costs of heating and thevolumes of kerogen breaker compound described by the kerogen breakervolume value 210 or the bottom hole heat up value 212 or bothcorresponding to the identified estimated production value 240.

FIG. 3 is flow chart that shows an example of a process 300 foradjusting kerogen breaker volume values. In some implementations, theprocess 300 can be performed at least in part by the example system 19of the example well system 10 of FIG. 1 or by the example system 200 ofFIG. 2.

In the process 300, a hydraulic fracture model is provided. In someimplementations, the hydraulic fracture model can be the examplehydraulic fracture model 220. In some implementations, the hydraulicfracture model can be configured to determine the discrete fracturenetwork (DFN) further based on a second value representative of anamount of heat to apply to a hydrocarbon reservoir, such as the rockformation 42. In some implementations, the hydraulic fracture model canbe configured to determine the DFN further based on one or more ofin-situ stresses in the reservoir field, pore pressures in the reservoirfield, injection plans of a fracturing job, heterogeneity in thereservoir formation, elastic stiffness properties of reservoir rocks,plastic strength properties of reservoir rocks, and mechanicalproperties of heterogeneities.

At 320 a first value is provided. The first value is representative of avolume of kerogen breaker in fracturing fluid. In some implementations,the first value can be the example kerogen breaker volume value 210.

At 330 a discrete fracture network (DFN) is determined. The example, theDFN is based on the hydraulic fracture model and the first value. Forexample, the example hydraulic fracture model 220 simulates a mainhydraulic fracturing stimulation based on the collection of modifiedshale formation properties, and the output of the hydraulic fracturemodel 220 is a DFN consisting of a description of a number of fractures,wherein each fracture can be characterized by one or more of length,width, height, and orientation. In some implementations, the DFN can bedescriptive of one or more of new fractures that are predicted to becreated based on the hydraulic fracturing model, modified shaleproperties predicted to be modified based on the hydraulic fracturingmodel, and reactivated fractures that are predicted to be reactivatedbased on the hydraulic fracturing model and the modified shaleproperties.

At 340 a geomechanical model is determined. The geomechanical model isdetermined based on the DFN. For example, the geomechanical model can bethe example geomechanical model 230. The geomechanical model isconfigured to receive the DFN and estimate an amount of hydrocarbonproduction that the rock formation 42 can provide based on the DFN. Insome implementations, the geomechanical model can be configured topredict the evolution of at least one of stress fields, deformation, anddamage in the reservoir based on one or more of in-situ stresses in thereservoir field, pore pressures in the reservoir field, rock masses ofreservoir layers, the DFN, constitutive models of rock mass thatdescribe stress-deformation-failure processes of reservoirs underloading modes, mechanical properties of rock masses, mechanicalproperties of fractures, fluid mechanical interaction parameters, andthermal mechanical coupling parameters.

At 350 a reservoir model is determined. The reservoir model is based onthe DFN. For example, the reservoir model can be the example reservoirmodel 232. The reservoir model is configured to receive the DFN andestimate an amount of hydrocarbon production that the rock formation 42can provide based on the DFN.

At 360, a hydrocarbon production volume is determined. The hydrocarbonproduction volume is an estimate based on the amounts of hydrocarbonproduction estimated by the geomechanical model and the reservoir modelfor the given first value. In some implementations, the hydrocarbonproduction volume can be the example estimated production value 240. Insome implementations, the reservoir model can be configured to predictthe evolution of multiphase flow and pressure fields in the reservoirbased on one or more of reservoir pressure distribution parameters,reservoir temperature distribution parameters, multiphase flow modelsfor fluid flow in rock, multiphase flow models for fluid flow in theDFN, thermal conduction models, thermal convection models, porosityparameters, permeability parameters, saturation parameters, thermalconduction property parameters, thermal convection property parameters,well location parameters, well drawdown plan parameters, and welltemperature parameters.

At 370, the first value is adjusted based on the determined hydrocarbonproduction volume. In some implementations the first value can beadjusted by the example adjustment module 250. For example, the firstvalue can be raised or lowered to effect an increase or decrease in theestimated production value 240.

In some implementations, the first value can have an associated monetarycost (for example, the cost of kerogen breaker compound) and theestimated hydrocarbon production value (for example, the market price ofcrude oil) can have an associated monetary value, and the first valuecan be adjusted to increase the difference between the costs andresulting estimated value (for example, increase net profit).

At 380, a flow of kerogen breaker in fracturing fluid to a hydrocarbonreservoir is adjusted based on the adjusted first value. For example,the example adjusted kerogen breaker volume value 210 can be used aspart of a control routine that directs the operation of the examplevalve 260. In some implementations, the flow of kerogen breaker infracturing fluid to the rock formation 42 can be based on an adjustedfirst value that increases the difference between the value ofhydrocarbon expected to be extracted by the well system 10 and cost ofthe amount of kerogen breaker compound used as part of the extractionprocess.

In some implementations, the first value can be adjusted at 370 based onan actual hydrocarbon production volume. For example, as the valve 260is operated to control the volume of kerogen breaker compound that isdelivered to the rock formation 42, the amount of hydrocarbons extractedfrom the rock formation 42 may not be the exact amount predicted by thegeomechanical model 230 and the reservoir model 232. In such examples,the actual value of the produced hydrocarbons can be greater or lessthan the value of the estimated production volume, and the first valuecan be adjusted to increase the difference between the costs andresulting actual value (for example, increase net profit).

In some implementations, a second value representative of an amount ofheat to apply to the hydrocarbon reservoir can be provided, the DFN canbe determined based on the second value, the second value can beadjusted based on the hydrocarbon production volume, and the amount ofheat to apply to the hydrocarbon reservoir can be adjusted based on theadjusted second value. For example, the example bottom hole heat upvalue 212 can represent an amount of heat energy or heat-producingmaterial that can be used to dissipate an amount of kerogen and affectthe amount of hydrocarbon produced by the example well system 10.

In some implementations, the volume of kerogen breaker in fracturingfluid can have a material cost, the hydrocarbon production volume canhave a market value, and adjusting the first value can includedetermining a difference between the market value and the material costand adjusting the first value to increase the difference. In someimplementations, the amount of heat can have a heating cost, thehydrocarbon production volume can have a market value, and adjusting thesecond value can include determining a difference between the marketvalue and the heating cost and adjusting the second value to increasethe difference.

For example, the bottom hole heat up value 212 may indicate that $10,000worth of acid and base would need to be delivered down hole to generatea predetermined amount of kerogen-dissipating heat, and the kerogenbreaker volume value 210 may indicate that $5,000 worth of breakercompound would need to be delivered down hole to chemically dissipate apredetermined about of kerogen, and the estimated production value 240can indicate that $100,000 worth of hydrocarbons could be extracted as aresult. This would result in a $−10,000−$5,000+$100,000=$85,000 netgain. The system 200 can, for example, adjust the kerogen breaker volumevalue 210 to indicate that $6,000 worth of breaker compound could beused to produce an estimated production value 240 having a worth of$110,000, or a $94,000 net gain. In such an example, the system 200 canselect the latter kerogen breaker volume value 210 over the firstbecause the latter value provides a greater net return on investment inbreaker compounds and heat than the former value (for example, $94,000versus $85,000, an additional $9,000 return on an additional $1,000investment).

In some implementations, the process 300 can include extracting a volumeof hydrocarbon from the hydrocarbon reservoir based on the volume ofkerogen breaker in fracturing fluid, and adjusting the first value basedon the extracted volume. In some implementations, the process 300 caninclude extracting a volume of hydrocarbon from the hydrocarbonreservoir based on the volume of kerogen breaker in fracturing fluid,and adjust the second value based on the extracted volume. For example,the well system 10 may initially be configured to deliver the $5,000worth of breaker compound down hole, and extract $100,000 worth ofhydrocarbon as a result. The control system 200 can adjust the valve 260to increase the amount of breaker compound being delivered down hole anddetect that an additional amount of hydrocarbon is being produced fromthe rock formation 42. In some implementations, the control system 200can adjust the kerogen breaker volume value 210, the bottom hole heat upvalue 212, or both, based on the increases and decreases in thehydrocarbon volumes that can be extracted as a result, for example, toimprove production volumes or profit margins for the amounts ofhydrocarbon that can be extracted as a result.

A number of implementations have been described. Nevertheless, it willbe understood that various modifications may be made without departingfrom the spirit and scope of the disclosure. For example, exampleoperations, methods, or processes described herein may include moresteps or fewer steps than those described. Further, the steps in suchexample operations, methods, or processes may be performed in differentsuccessions than that described or illustrated in the figures. Asanother example, although certain implementations described herein maybe applicable to tubular systems (for example, drill pipe or coiledtubing), implementations may also utilize other systems, such aswireline, slickline, e-line, wired drill pipe, wired coiled tubing, andotherwise, as appropriate. As another example, some criteria, such astemperatures, pressures, and other numerical criteria are described aswithin a particular range or about a particular value. In some aspects,a criterion that is about a particular value is within 5-10% of thatparticular value. Accordingly, other implementations are within thescope of the following claims.

What is claimed is:
 1. A method for treating a geologic formation,comprising: receiving a hydraulic fracture model configured to simulatea main hydraulic fracturing stimulation; receiving a first valuerepresentative of a volume of kerogen breaker in a fracturing fluid;determining a discrete fracture network (DFN) comprising: a descriptionof a number of fractures, wherein each fracture is characterized by oneor more of length, width, height, and orientation that are estimatedbased on the hydraulic fracture model; and predicted effects of thevolume of kerogen breaker represented by the first value on initiationand propagation of the fractures and sustainability of the fracturesduring hydrocarbon extraction; determining a first hydrocarbonproduction volume value based on a geomechanical model and the DFN;determining a second hydrocarbon production volume value based on areservoir model and the DFN; determining a third estimated hydrocarbonproduction volume based on the determined first hydrocarbon productionvolume value and the determined second hydrocarbon production volumevalue; adjusting the first value based on the determined third estimatedhydrocarbon production volume value; adjusting a volume of kerogenbreaker in the fracturing fluid based on the adjusted first value;providing the adjusted volume of kerogen breaker in the fracturing fluidto a hydrocarbon reservoir in a subterranean zone; modifying shalestiffness and strength properties in the hydrocarbon reservoir based onthe adjusted volume of kerogen breaker; and extracting a volume ofhydrocarbon from the hydrocarbon reservoir based on the modified shalestiffness and strength properties in the hydrocarbon reservoir, whereinthe third estimated hydrocarbon production volume is predictive of theextracted volume.
 2. The method of claim 1, further comprising:providing a second value representative of an amount of heat to apply tothe hydrocarbon reservoir in the subterranean zone; adjusting the secondvalue based on the third estimated hydrocarbon production volume value;wherein, determining the DFN is further based on the second value; andadjusting the amount of heat to apply to the hydrocarbon reservoir inthe subterranean zone is further based on the second value.
 3. Themethod of claim 2, wherein the amount of heat has a heating cost, thethird estimated hydrocarbon production volume has a market value, andadjusting the second value comprises determining a difference betweenthe market value and the heating cost and adjusting the second value toincrease the difference.
 4. The method of claim 2, further comprisingadjusting the second value based on the extracted volume, wherein theextracted volume is based on the volume of kerogen breaker in thefracturing fluid.
 5. The method of claim 1, wherein the volume ofkerogen breaker in the fracturing fluid has a material cost, theestimated third hydrocarbon production volume has a market value, andadjusting the first value comprises determining a difference between themarket value and the material cost and adjusting the first value toincrease the difference.
 6. The method of claim 1, wherein the DFN isdescriptive of one or more of new fractures that are predicted to becreated based on the hydraulic fracture model, modified shale propertiespredicted to be modified based on the hydraulic fracture model, andreactivated fractures that are predicted to be reactivated based on thehydraulic fracture model and the modified shale properties.
 7. Themethod of claim 1, wherein the hydraulic fracture model is configured todetermine the DFN further based on one or more of in-situ stresses inthe hydrocarbon reservoir, pore pressures in the hydrocarbon reservoir,injection plans of a fracturing job, heterogeneity in the hydrocarbonreservoir, elastic stiffness properties of reservoir rocks, plasticstrength properties of reservoir rocks, and mechanical properties ofheterogeneities, and the DFN comprises a number of fractures eachcharacterized by one or more of fracture length, fracture width,fracture height, and fracture orientation.
 8. The method of claim 1,wherein the geomechanical model is configured to predict evolution of atleast one of stress fields, deformation, and damage in the hydrocarbonreservoir based on one or more of in-situ stresses in the hydrocarbonreservoir, pore pressures in the hydrocarbon reservoir, rock masses ofreservoir layers, the DFN, constitutive models of rock mass thatdescribe stress-deformation-failure processes of reservoirs underloading modes, mechanical properties of rock masses, mechanicalproperties of fractures, fluid mechanical interaction parameters, andthermal mechanical coupling parameters.
 9. The method of claim 1,wherein the reservoir model is configured to predict evolution ofmultiphase flow and pressure fields in the hydrocarbon reservoir basedon one or more of reservoir pressure distribution parameters, reservoirtemperature distribution parameters, multiphase flow models for fluidflow in rock, multiphase flow models for fluid flow in the DFN, thermalconduction models, thermal convection models, porosity parameters,permeability parameters, saturation parameters, thermal conductionproperty parameters, thermal convection property parameters, welllocation parameters, well drawdown plan parameters, and well temperatureparameters.
 10. The method of claim 1, further comprising adjusting thefirst value based on the extracted volume, wherein the extracted volumeis based on the volume of kerogen breaker in the fracturing fluid.
 11. Asystem for hydraulic fracturing comprising: a control system comprisingone or more processors; and a non-transitory computer-readable mediumstoring instructions executable by the one or more processors to performoperations comprising: receive a first value representative of a volumeof kerogen breaker in a fracturing fluid; determining a discretefracture network (DFN) comprising: a description of a number offractures, wherein each fracture is characterized by one or more oflength, width, height, and orientation that are estimated based on ahydraulic fracture model; and predicted effects of the volume of kerogenbreaker represented by the first value on initiation and propagation ofthe fractures and sustainability of the fractures during hydrocarbonextraction; determining a first hydrocarbon production volume value, bya geomechanical model based on the DFN; determining a second hydrocarbonproduction volume value, by a reservoir model based on the DFN;determining an third estimated hydrocarbon production volume based onthe determined first hydrocarbon production volume value and thedetermined second hydrocarbon production volume value; adjusting, by anadjustment module, the first value based on the determined thirdestimated hydrocarbon production volume; controlling, by the controlsystem, a valve to adjust a volume of kerogen breaker in the fracturingfluid based on the adjusted first value; and providing, based on thecontrolling, the adjusted volume of kerogen breaker in the fracturingfluid to a hydrocarbon reservoir in a subterranean zone, wherein shalestiffness and strength properties in the hydrocarbon reservoir aremodified based on the adjusted volume of kerogen breaker such that thethird estimated hydrocarbon production volume is predictive of a volumeof hydrocarbon extracted from the hydrocarbon reservoir based on themodified shale stiffness and strength properties in the hydrocarbonreservoir.
 12. The system of claim 11, wherein: the hydraulic fracturemodel is configured to determine the discrete fracture network (DFN)further based on a second value representative of an amount of heat toapply to the hydrocarbon reservoir; and the adjustment module is furtherconfigured to adjust the second value based on the third estimatedhydrocarbon production volume.
 13. The system of claim 12, wherein theamount of heat has a heating cost, the third estimated hydrocarbonproduction volume has a market value, and the adjustment module isfurther configured to adjust the second value based on determining adifference between the market value and the heating cost and adjustingthe second value to increase the difference.
 14. The system of claim 12,further comprising a valve configured to adjust delivery of heatprovided to a hydrocarbon reservoir based on the adjusted second value.15. The system of claim 11, wherein the volume of kerogen breaker in thefracturing fluid has a material cost, the third estimated hydrocarbonproduction volume has a market value, and the adjustment module isfurther configured to adjust the second value based on determining adifference between the market value and the material cost and adjustingthe first value to increase the difference.
 16. The system of claim 11,wherein the DFN is descriptive of one or more of new fractures that arepredicted to be created based on the hydraulic fracture model, modifiedshale properties predicted to be modified based on the hydraulicfracture model, and reactivated fractures that are predicted to bereactivated based on the hydraulic fracture model and the modified shaleproperties.
 17. The system of claim 11, wherein the hydraulic fracturemodel is configured to determine the DFN further based on one or more ofin-situ stresses in the hydrocarbon reservoir, pore pressures in thehydrocarbon reservoir, injection plans of a fracturing job,heterogeneity in the hydrocarbon reservoir, elastic stiffness propertiesof reservoir rocks, plastic strength properties of reservoir rocks, andmechanical properties of heterogeneities, and the DFN comprises a numberof fractures each characterized by one or more of fracture length,fracture width, fracture height, and fracture orientation.
 18. Thesystem of claim 11, wherein the geomechanical model is configured topredict evolution of at least one of stress fields, deformation, anddamage in the hydrocarbon reservoir based on one or more of in-situstresses in the hydrocarbon reservoir, pore pressures in the hydrocarbonreservoir, rock masses of reservoir layers, the DFN, constitutive modelsof rock mass that describe stress-deformation-failure processes ofreservoirs under loading modes, mechanical properties of rock masses,mechanical properties of fractures, fluid mechanical interactionparameters, and thermal mechanical coupling parameters.
 19. The systemof claim 11, wherein the reservoir model is configured to predictevolution of multiphase flow and pressure fields in the hydrocarbonreservoir based on one or more of reservoir pressure distributionparameters, reservoir temperature distribution parameters, multiphaseflow models for fluid flow in rock, multiphase flow models for fluidflow in the DFN, thermal conduction models, thermal convection models,porosity parameters, permeability parameters, saturation parameters,thermal conduction property parameters, thermal convection propertyparameters, well location parameters, well drawdown plan parameters, andwell temperature parameters.